Band 2, Heft 1

The use of hydraulic fracturing has been greatly increased in the petroleum industry over the past few decades. However, the issue of screen-out has remained since proppants were first used in hydraulic fracturing. Due to the serious consequences caused by the screen-out, it is desirable to avoid or delay it where possible in the implementation process of hydraulic fracturing. This paper provides a mathematical method for estimating the screen-out time during hydraulic fracturing in vertical wells. The model result is consistent with field observations. Sensitivity analyses in this paper show that the viscosity of the fracturing fluid, proppant density, injection rate and ratio of proppant volume to fracturing fluid volume significantly affect the screen-out time and characteristics of the proppant pile. This model can be used as a general tool for optimizing fracturing parameters in vertical wells in order to minimize the screen-out effect.

Traditional well test models for CO 2 flooding neglect dynamic mass transfer and over-simplify transient viscosity in a transition zone, making them unable to deal with more complicated and heterogeneous field situations. To eliminate this restriction/limitation, this study proposes a comprehensive transient pressure model that incorporates a convection– diffusion mass transfer process. It actually is an enhanced three-region composite model that includes CO 2 bank, transition zone, and oil zone. Type curves are plotted and four flow regimes are identified: early radial flow, transition flow, pseudo-radial flow, and boundary-dominated flow. In addition, it is found that mass transfer mainly leads the transition flow regime to slower slope change, and pseudo radial flow regime with lower straight line compared with a case neglects the mass transfer in a transition zone. Moreover, it shows that a smaller injection rate and a longer injection period are better for viscosity reduction than a larger injection rate and a shorter injection period.

We report methane (structure I) and methane/ethane (structure II) hydrate phase equilibrium data with calcium bromide (32 wt%) and a mixture of calcium bromide (20 wt%) + monoethylene glycol (20 wt%) solutions for pressures up to 200 MPa. As expected for thermodynamic hydrate inhibitors, the salt and glycol cause the hydrate phase equilibrium boundary to shift to lower temperatures and higher pressures. These data are the first to be reported for these systems, which are particularly useful as calcium bromide is widely used in drilling fluids and hydrate formation is a growing concern in well completion and workover fluids. The measured experimental data were compared with commonly used hydrate prediction tools to assess their reliability.

Vitrisol ® , a novel desulphurization process that is 100% selective for H 2 S removal from industrial gases containing CO 2 , can be described with the following overall reaction equation: H2S+0.5O2→H2O+SO(s)$${H_2}S + 0.5{O_2} \to {H_2}O + {S^O}(s)$$ The performance of Vitrisol ® is demonstrated for two typical applications in shale gas production by comparing them to a standard amine treating process. The remainder toxic, acid gas produced by the latter technology is compressed for acid gas injection. From the results it can be concluded that significant reductions in utilities can be achieved by using Vitrisol ® as depicted in the energy consumptions of the overall process. Contrary to the amine process, Vitrisol ® does not require additional treatment of the non-toxic off-gas stream as the H 2 S is directly converted to crystalline sulphur. This study illustrates clearly that it is advantageous to first remove H 2 S from a gas stream containing both H 2 S and CO 2 prior to CO 2 removal to reduce utilities consumption.

Sulfur deposition in the reservoir formation and its impact on well productivity and ultimate recovery has been investigated for close to 50 years. Experimental measurements and numerical modeling studies have focused on the phase behavior of the sulfur-sour gas mixture system and the flow of sulfur and natural gas through the formation. The key results from these investigations are reviewed in this paper. The implementation of the insights gained over these 50 years of research into the field development planning and operation of sour gas fields is described.